The present invention relates to a process for conditioning natural gas containing liquid hydrocarbons, for pipeline transport.
Natural gas can be classified into two broad categories on the basis of chemical composition. These categories are natural gas, which contains economically recoverable amounts of condensable hydrocarbons, and natural gas not containing economically recoverable amounts of condensable hydrocarbons. The present invention deals with conditioning natural gas of the first category comprising gaseous hydrocarbons and liquid hydrocarbons.
On producing natural gas in the field, heavier hydrocarbon components in the gas may condense together with water as a result of a drop in temperature of the gas as it is transferred from a subsurface well to a surface location. Although the presence of water vapor is not particularly objectionable, water in the liquid or solid state can create problems. Water in the liquid state tends to accelerate corrosion of the pipeline system through which the gas is transported, especially when considerable amounts of acidic components, such as carbon dioxide, are present in the gas. Solid hydrates can greatly restrict or actually even stop the flow of gas through a pipeline.
In order to eliminate or at least to minimize the above negative effects in natural gas pipeline transport, it is normal practice to reduce the water content of the raw natural gas to such a concentration that the water dew-point temperature of the gas is somewhat lower than the lowest temperature to be encountered in the pipeline system through which the gas will be transported. For dehydrating a natural gas stream it is known to separate the production stream into a condensate phase and a gas phase, whereafter the water and water vapor present in the gas phase are removed therefrom by scrubbing the gas under pressure with a suitable absorbent or desiccant, such as diethylene and triethylene glycol, having an affinity for water. The bulk of the water in the condensate phase is normally separated by gravity settling. However, the settling tends to leave the dissolved water and water droplets smaller than about 50 micrometers suspended in the hydrocarbon condensate.
Since the processing of a natural gas stream is usually handled in plants which are located at considerable distances from the wells producing the natural gas, it is a common practice to transport both condensate and vapor phases through a single pipeline to the processing plants. By feeding the only partially dried condensate into a transport pipeline together with dry gas, the water still present in the condensate will start to evaporate into the gas either until no water is left in the condensate, or until the gas is saturated with water vapor at the prevailing temperature, depending on the gas/condensate feed ratio. In the latter case the condensate has to be further dried, prior to being supplied into the pipeline since otherwise, condensed water formed upon decrease of the gas temperature, e.g. because of the gradual expansion during pipeline transport, will wet the wall of the pipeline, and may result in corrosion, particularly if the gas stream contains a substantial percentage of acidic components. If required in view of the above considerations, the condensate may be further dried by bringing it in intimate contact with dry gas, such as already dried natural gas, whereby the water in the condensate is stripped therefrom by the gas. This process, however, requires additional equipment, such as a stripping gas absorber.
The present invention deals with the situation that the gas/condensate feed ratio is so high that the dried gas can strip out or "absorb" all the water initially present in the wet condensate without exceeding the dewpoint specification. This means that if dried gas and wet condensate are fed together into a pipeline, there is no risk of corrosion or the formation of hydrates after the water evaporation process is complete. Corrosion and/or flow hampering problems may however, occur in the first part of the pipeline when the water in the condensate is still evaporating into the gas. The total pipeline length required for complete evaporation of the water in the condensate depends on the gas/condensate ratio, the water/condensate ratio upon introduction into the pipeline, the gas/condensate interfacial area in the pipeline and the temperature prevailing during the evaporation.
The evaporation of water from condensate is a rather longlasting process since physically dissolved water evaporates from the condensate, and due to the so decreased water concentration in the condensate, water droplets physically dissolve in the condensate. On account of the poor solubility of water in condensate the first step of the evaporation process proceeds very slowly. During the process the rate of evaporation further decreases for two reasons, viz. decreasing interfacial area dropsize, and increasing water vapor pressure in the gas.
Taking further into account the rather high flow rates--normally about 5-10 m/sec for the gas and about 3-5 m/sec for the condensate--in gas transport pipelines, it will be understood that the length of the pipeline necessary for evaporation of the water is in the order of magnitude of several kilometers. This pipeline length may be somewhat shortened by spraying atomized condensate into the gas flow instead of just feeding the condensate as a thick stream into the gas pipeline as normally practiced. Atomization of the condensate into the gas flow results in a considerable increase of the interfacial area between the condensate and the gas, which advantageously influences the rate of evaporation of dissolved water from the condensate into the gas phase. Since the solubility of water in condensate remains poor the total rate of evaporation will be such that a considerable length of pipeline remains required.
The object of the present invention is to substantially eliminate the risk of corrosion during transport of wet natural gas in the first part of a gas pipeline where the water evaporation still proceeds.